Hydrocarbon based carrier fluid

ABSTRACT

Y-grade NGL or L-grade is used as a carrier fluid to transport one or more chemical additives into a hydrocarbon bearing reservoir to treat the hydrocarbon bearing reservoir. The Y-grade NGL or L-grade and the chemical additives may be chilled and/or foamed.

CROSS-REFERENCE TO RELATED APPLICATION

This application is a continuation of U.S. patent application Ser. No.15/400,345, filed Jan. 6, 2017, which claims priority to U.S.Provisional Application Ser. No. 62/319,848, filed Apr. 8, 2016, each ofwhich is incorporated by reference herein in its entirety.

BACKGROUND Field

Embodiments of the disclosure relate to transporting one or morechemicals using a hydrocarbon based carrier fluid. More particularly, itrelates to using an unfractionated hydrocarbon mixture (such as Y-GradeNGL or L-Grade) as a carrier fluid to transport one or more chemicaladditives into a hydrocarbon bearing reservoir to improve or remediateproductivity issues.

Description of the Related Art

Flow restrictions in oil and gas wells tend to reduce the productionrate over a period of time. Typically, the fluid flowing from ahydrocarbon bearing reservoir leaves behind solid residues, bothinorganic and organic, in a portion of the formation proximate the welland in tubing, piping, valves, and the like which form the wellstructure.

In the operation of a well, there are many processes which may act toreduce production from the well. Hydrocarbon production is typicallylimited by two major reservoir factors: porosity and permeability. Evenif the porosity is adequate, the effective permeability to thehydrocarbon flow may be limited. When more than one fluid is present ina permeable system, the flow of each is affected by the amount anddistribution of the other(s); in particular the relative flows orrelative permeability are affected by which fluid is the “wetting”phase, that is the fluid that wets the surfaces of the reservoir rock.Aqueous-based fluid injected during well treatments may saturate thepore spaces of the treated region, preventing the migration ofhydrocarbon into and through the same pore spaces.

Drilling fluids may contain chemicals which can reduce the ability ofthe formation to produce fluids by reacting with the formation and/orformation fluids to produce precipitates and/or scale. Retrogradecondensation may cause a condensate ring to accumulate near wellboreresulting in significant reduction in hydrocarbon flowrate. Thedeposition of scale, asphaltenes, and paraffin's may also inhibit flow.Furthermore, certain fluids may react with clays within the formation tocausing them to swell, further blocking the formation's ability to flow.As conventional examples, solvents are used to remove paraffin andasphaltene deposits; surfactants are used to modify formationwettability, modify capillary forces to increase oil mobility, and toeliminate near wellbore condensate blockage; acids are used to removeskin damage; and polymers are used to modify water viscosity to improvesweep or divert fluid flow within the subsurface reservoir.

In some instances, chemical treatments require a “carrier fluid” and/ora displacement fluid to transport the chemical treatment and place it atthe appropriate location in the wellbore or subsurface formation. Thereis a need for methods to carry in suspension and transport chemicalcompositions for cleaning wellbore and near-wellbore areas from damagerelated to drilling, work over operations and degradation of the nearwellbore and subsurface formation especially in low pressure formations.There is an additional need to perform cleaning in a manner such that anoperator may precisely control the location of the remedial chemicaltreatment.

SUMMARY

A method of transporting a chemical additive to a hydrocarbon bearingreservoir comprises mixing the chemical additive with a carrier fluid toform a treatment fluid, wherein the carrier fluid includes anunfractionated hydrocarbon mixture, and pumping the treatment fluid intothe hydrocarbon bearing reservoir.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a plan schematic of a carrier fluid system according to oneembodiment.

FIG. 2 shows a plan schematic of a carrier fluid system according to oneembodiment.

FIG. 3 shows a plan schematic of a carrier fluid system according to oneembodiment.

FIG. 4 shows a plan schematic of a Y-Grade NGL recovery system that canbe used to create Y-Grade NGL for use in the embodiments describedherein.

FIG. 5 shows a plan schematic of an L-Grade recovery system that can beused to create L-Grade for use in the embodiments described herein.

To facilitate understanding, identical reference numerals have beenused, where possible, to designate identical elements that are common tothe figures. It is contemplated that elements disclosed in oneembodiment may be beneficially utilized on other embodiments withoutspecific recitation.

DETAILED DESCRIPTION

Embodiments of the disclosure include carrier fluids used to transportone or more chemical additives (e.g. chemical compositions) into ahydrocarbon bearing reservoir. One or more of the carrier fluids maycomprise an unfractionated hydrocarbon mixture, such as Y-Grade naturalgas liquids (referred to herein as Y-Grade NGL) or L-Grade fluids(referred to herein as L-Grade).

Y-Grade NGL is an un-fractionated hydrocarbon mixture comprising ethane,propane, butane, isobutane, and pentane plus. Pentane plus comprisespentane, isopentane, and/or heavier weight hydrocarbons, for examplehydrocarbon compounds containing at least one of C5 through C8+. Pentaneplus may include natural gasoline for example.

Typically, Y-Grade NGL is a by-product of de-methanized hydrocarbonstreams that are produced from shale wells and transported to acentralized facility. Y-Grade NGL can be locally sourced from a splitterfacility, a gas plant, and/or a refinery and transported by truck orpipeline to a point of use. In its un-fractionated or natural state(under certain pressures and temperatures, for example within a range of250-600 psig and at wellhead or ambient temperature), Y-Grade NGL has nodedicated market or known use. Y-Grade NGL must undergo processingbefore its true value is proven.

The Y-Grade NGL composition can be customized for handling as a liquidunder various conditions. Since the ethane content of Y-Grade NGLaffects the vapor pressure, the ethane content can be adjusted asnecessary. According to one example, Y-Grade NGL may be processed tohave a low ethane content, such as an ethane content within a range of3-12 percent, to allow the Y-Grade NGL to be transported as a liquid inlow pressure storage vessels. According to another example, Y-Grade NGLmay be processed to have a high ethane content, such as an ethanecontent within a range of 38-60 percent, to allow the Y-Grade NGL to betransported as a liquid in high pressure pipelines.

Y-Grade NGL differs from liquefied petroleum gas (“LPG”). One differenceis that LPG is a fractionated product comprised of primarily propane, ora mixture of fractionated products comprised of propane and butane.Another difference is that LPG is a fractioned hydrocarbon mixture,whereas Y-Grade NGL is an unfractionated hydrocarbon mixture. Anotherdifference is that LPG is produced in a fractionation facility via afractionation train, whereas Y-Grade NGL can be obtained from a splitterfacility, a gas plant, and/or a refinery. A further difference is thatLPG is a pure product with the exact same composition, whereas Y-GradeNGL can have a variable composition.

In its unfractionated state, Y-Grade NGL is not an NGL purity productand is not a mixture formed by combining one or more NGL purityproducts. An NGL purity product is defined as an NGL stream having atleast 90% of one type of carbon molecule. The five recognized NGL purityproducts are ethane (C2), propane (C3), normal butane (NC4), isobutane(IC4) and natural gasoline (C5+). The unfractionated hydrocarbon mixturemust be sent to a fractionation facility, where it is cryogenicallycooled and passed through a fractionation train that consists of aseries of distillation towers, referred to as deethanizers,depropanizers, and debutanizers, to fractionate out NGL purity productsfrom the unfractionated hydrocarbon mixture. Each distillation towergenerates an NGL purity product. Liquefied petroleum gas is an NGLpurity product comprising only propane, or a mixture of two or more NGLpurity products, such as propane and butane. Liquefied petroleum gas istherefore a fractionated hydrocarbon or a fractionated hydrocarbonmixture.

In one embodiment, Y-Grade NGL comprises 30-80%, such as 40-60%, forexample 43%, ethane, 15-45%, such as 20-35%, for example 27%, propane,5-10%, for example 7%, normal butane, 5-40%, such as 10-25%, for example10%, isobutane, and 5-25%, such as 10-20%, for example 13%, pentaneplus. Methane is typically less than 1%, such as less than 0.5% byliquid volume.

In one embodiment, Y-Grade NGL comprises dehydrated, desulfurizedwellhead gas condensed components that have a vapor pressure of not morethan about 600 psig at 100 degrees Fahrenheit (° F.), with aromaticsbelow about 1 weight percent, and olefins below about 1% by liquidvolume. Materials and streams useful for the embodiments describedherein typically include hydrocarbons with melting points below about 0degrees Fahrenheit (° F.).

In one embodiment, Y-Grade NGL may be mixed with a viscosity increasingagent, a nonionic surfactant, and/or a crosslinking agent. Y-Grade NGLmay be mixed with the nonionic surfactant to create foam. The viscosityincreasing agent, the nonionic surfactant, and/or the crosslinking agentmay be mixed with a solubilizing fluid for subsequent mixture with theY-Grade NGL. The solubilizing fluid may comprise fractionated or refinedhydrocarbons, such as C₃, C₄, C₅, C₆, C₇, C₈, C₉, and mixtures thereof.The solubilizing fluid may comprise C3+ hydrocarbons, including propane,butane, pentane, naphtha, toluene, diesel, natural gasoline, and anycombination thereof.

The advantages of using Y-Grade NGL as a carrier fluid is that the fluidis devoid of free water and available at lower cost compared to otherwaterless alternatives that are currently employed (such as supercritical state CO₂), is 100 percent compatible with subsurfacehydrocarbon bearing formations, is a natural solvent, and is fast toclean-up as it is energized by the lighter hydrocarbon components (suchas C₂ & C₃).

L-Grade is an unfractionated hydrocarbon mixture comprising natural gasliquids, condensate (including aromatics), and traces of water, carbondioxide, nitrogen, and/or hydrogen sulfide. The natural gas liquids inthe L-Grade mixture comprise ethane, propane, butane, isobutane, andpentane plus. Pentane plus comprises pentane, isopentane, and/or heavierweight hydrocarbons, for example hydrocarbon compounds containing C5through C35. Pentane plus may include natural gasoline for example.

Typically, L-Grade is a by-product of de-methanized hydrocarbon streamsthat are produced from shale wells and transported to a centralizedfacility. L-Grade typically includes natural gas liquids and condensatewith an API gravity ranging between 50 degrees and 75 degrees. In itsun-fractionated or natural state (under certain pressures andtemperatures, for example within a range of 250-600 psig and at wellheador ambient temperature) L-Grade has no dedicated market or known use.L-Grade must undergo processing before its true value is proven.

L-Grade differs from condensate in that L-Grade is stored at a pressurebetween about 230 psig to about 600 psig, whereas condensate is storedat atmospheric conditions (e.g. pressure and temperature).

L-Grade can be recovered from a hydrocarbon stream that is collectedfrom the wellhead or production header of one or more unconventionalresource wells, typically referred to as shale wells, via flashseparation at pressures that are typically below 600 psig. This isaccomplished by utilizing flash separation operated at low enoughpressure to reject the vast majority of methane from the hydrocarbonstream, but at high enough pressure to retain a significant portion ofthe ethane plus mixture.

FIG. 1 is a plan view of a carrier fluid system 100 according to oneembodiment. The carrier fluid system 100 includes a carrier fluidstorage unit 80, a chemical additive unit 40, and one or more highpressure pumps 105. A carrier fluid, such as an unfractionatedhydrocarbon mixture (e.g. Y-Grade NGL or L-Grade), from the carrierfluid storage unit 80 is pumped to a control valve V1 through piping 70by a pump 75 and into piping 74.

A chemical additive from the chemical additive unit 40 is pumped throughpiping 60 by a dosing pump 50 into piping 74. Although only one chemicaladditive unit 40 is shown, the carrier fluid system 100 may include anynumber of chemical additive units 40 containing the same or differentchemical additives, all of which are pumped into piping 74 for mixturewith the carrier fluid. The chemical additive may be a solvent, asurfactant, a non-ionic surfactant, a polymer, an acid, anano-surfactant, a nano-polymer, a polymer coated nano-particle, anano-solvent, or any combination thereof.

The carrier fluid mixes with the chemical additive in piping 74 to forma treatment fluid. The treatment fluid is transferred from piping 74into the one or more high-pressure pumps 105. Any convenient pump may beused as the high-pressure pumps 105. The high-pressure pumps 105 boostthe pressure of the carrier fluid to a pressure of 250 psig or more,such as 250 psig to 10,000 psig, for example about 10,000 psig, andpumps the treatment fluid through piping 150 into piping 180, and frompiping 180 into a wellhead 190 (and through carbon steel tubing,stainless steel tubing, coiled tubing, or capillary tubing for example)for injection into a subsurface formation.

FIG. 2 is a plan view of a carrier fluid system 200 according to oneembodiment. The carrier fluid system 200 is similar to the carrier fluidsystem 100 but further includes a cooler 160, a liquid nitrogen source110, and one or more cryogenic pumps 130. The treatment fluid flows frompiping 150 through the cooler 160 to piping 180. Liquid nitrogen (fromthe liquid nitrogen source 110) flowing through the cooler 160 cools thepressurized treatment fluid to a temperature of 0° F. or lower, forexample as low as −60° F. The cooler 160 may be a shell-and-tube cooler,a tube-in-tube cooler, or other similar design, and is typically cooledby thermal contact with liquid nitrogen.

Liquid nitrogen from the liquid nitrogen source 110, which may be aliquid nitrogen storage unit, is transferred through piping 120 by oneor more cryogenic pumps 130. The cryogenic pumps 130 discharge liquidnitrogen through piping 140 to a control valve V2, and from the controlvalve V2 into the cooler 160 to cool the pressurized treatment fluidthat is flowing through the cooler 160. The low temperature, pressurizedtreatment fluid discharges from the cooler 160 into piping 180 and ispumped to the wellhead 190 for injection into a subsurface formation.Liquid nitrogen that is vaporized in the cooler 160 is discharged to anitrogen vent through piping 170.

The cryogenic components of the carrier fluid system 200, such as theliquid nitrogen source 110, the cryogenic pumps 130, the control valveV2, the cooler 160, and piping 120, 140, 150, 170, and/or 180 may bemade of material resistant to low temperatures and/or may be insulatedto avoid heat uptake and to enhance safety of operating personnel. Suchlow temperature resistant materials may include, but are not limited to,carbon steel, stainless steel, nickel, Inconel, and austenitic stainlesssteel. Supplemental cooling may also be included with any insulation orjacketing by routing tubing or piping through the insulation, or betweenthe insulation and the equipment, and providing additional liquidnitrogen through the tubing or piping.

FIG. 3 is a plan view of a carrier fluid system 300 according to oneembodiment. The carrier fluid system 300 is similar to the carrier fluidsystem 200 with one difference being that the cooler 160 has beenremoved and a vaporizer 135 has been added.

Liquid nitrogen obtained from the liquid nitrogen source 110 istransferred through piping 120 by one or more cryogenic pumps 130, whichdischarge the liquid nitrogen into the vaporizer 135 where the liquidnitrogen is converted into high pressure gaseous nitrogen. The highpressure gaseous nitrogen is discharged from the vaporizer 135 throughthe control valve V2 via piping 140 and directly into piping 180, whereit mixes with and cools the pressurized treatment fluid flowing frompiping 150 to generate foam. The foam (also referred to as the treatmentfluid) is then pumped into the wellhead 190 for injection into asubsurface formation.

In one embodiment, the treatment fluid is chilled to a temperature thatfreezes connate water located in the hydrocarbon bearing reservoir. Thefrozen water in the reservoir diverts the flow of any additionaltreatment fluid and allows placement of material at selected locationsin the reservoir.

In one embodiment, the treatment fluid (and in particular Y-Grade NGL orL-Grade in the treatment fluid) acts as a solvent to remediate paraffinand/or asphaltene located near wellbore and in the hydrocarbon bearingreservoir. In one embodiment, the treatment fluid (and in particularY-Grade NGL or L-Grade with a surfactant in the treatment fluid) is usedto remediate condensate blockage located in the hydrocarbon bearingreservoir.

In one embodiment, the treatment fluid may comprise a reverse emulsionof 5-10% inhibited water by volume, the Y-grade NGL or L-grade carrierfluid, the chemical additive, and a surfactant.

In one embodiment, carbon dioxide, a non-ionic surfactant, and/or anyother cooling agent may be used in place of or in addition to liquidnitrogen as described in the carrier fluid system 200 to chill thetreatment fluid.

In one embodiment, carbon dioxide, a non-ionic surfactant, and/or anyother foaming agent may be used in place of or in addition to liquidnitrogen as described in the carrier fluid system 300 to chill thetreatment fluid and/or generate foam.

In one embodiment, the treatment fluid is used to treat the hydrocarbonbearing reservoir by remediating (e.g. reducing and/or removing) one ormore materials from the reservoir. In one embodiment, the treatmentfluid is used to displace one or more materials from the reservoir toincrease the productivity of the reservoir.

FIG. 4 shows one embodiment of a Y-Grade NGL recovery system 900 forobtaining Y-Grade NGL that can be used with any of the embodimentsdescribed herein. As illustrated in FIG. 4, a stream of hydrocarbons areproduced from a first hydrocarbon bearing reservoir 910 to the surfacevia a first wellhead 920 where the produced hydrocarbon stream is flashseparated onsite by an onsite separator 930 into a wet gas stream (alsoreferred to as a natural gas stream) and a liquid stream. The naturalgas stream is transported, via pipeline for example, to a regionalnatural gas processing facility 940 where it is further processed, andthe liquid stream is transported to field storage for example where itis sold into the market.

The natural gas stream enters the natural gas processing facility 940where it is dehydrated and decontaminated of CO2, H2S, and N2. Thedehydrated and decontaminated natural gas stream is then expanded andcooled to condense out natural gas liquids. These natural gas liquids(“NGL”) are an unfractionated hydrocarbon mixture, which is referred toas Y-Grade NGL, raw mix, or unfractionated NGL. The remaining gas streamis transported to a pipeline for example where it is sold into themarket.

The unfractionated hydrocarbon mixture is a liquid mixture that has beencondensed from the natural gas stream at the natural gas processingfacility 940. The condensation process is the result of expanding andcooling the natural gas stream to condense out the unfractionatedhydrocarbon mixture, a process also referred to as de-methanizing thenatural gas stream. The unfractionated hydrocarbon mixture is thereforea natural byproduct of a de-methanized hydrocarbon stream.

The unfractionated hydrocarbon mixture is then transported via apipeline for example to a targeted reservoir for use as a carrier fluidas described herein. The carrier fluid may be injected via a secondwellhead 950 (such as wellhead 190) into a second hydrocarbon bearingreservoir 970 using the embodiments described herein.

FIG. 5 shows one embodiment of an L-Grade recovery system 3000 forobtaining L-Grade that can be used with any of the embodiments describedherein. The L-Grade recovery system 3000 is transported to the wellsiteand connected to the hydrocarbon stream 10 (produced from one or morewells at the wellsite) via an inlet of a three-phase high pressurehorizontal separator 40 with operating pressure and throughput ratecontrolled by control valve V20. The hydrocarbon stream 10 is separatedby the separator 40 into three unique components including L-Grade,water, and natural gas via gravity segregation at a specified pressure.

Pressurized L-Grade exits the separator 40 via transfer line 310 that iscontrolled by control valve V320 and rate metered by turbine meter M330to pressurized L-Grade storage vessels 350. Check valve C340 preventsback flow from the L-Grade storage vessels 350. The L-Grade storagevessels 350 are nitrogen blanketed by a nitrogen blanketing systemcomprising a nitrogen header 360, control valve V370, and liquidnitrogen storage tank 400. Liquid nitrogen from the storage tank 400 vialine 390 is vaporized in a nitrogen vaporizer 380 and discharged throughthe control valve V370 to the nitrogen header 360, which distributesnitrogen into the L-Grade storage vessels 350. The L-Grade cansubsequently be used as a carrier fluid and injected into a hydrocarbonbearing reservoir.

Water from separator 40 is transferred via line 110 to an atmosphericwater storage and/or disposal facility on the oil and gas leases forexample. The flow rate and pressure of the water from the separator 40is controlled by valve V130 and metered by turbine meter M120.

Natural gas from the separator 40 is transferred via line 50 throughcontrol valve V70 and into a suction scrubber 80. Entrained liquids areremoved from the natural gas stream by the suction scrubber 80 andtransferred to the atmospheric water storage and/or disposal facilityvia drain line 100. The suction scrubber 80 can be by-passed by openingcontrol valve V60, closing control valve V70, and allowing the naturalgas stream to move through line 90.

A liquid free natural gas stream exits the suction scrubber 80 via line140, flows through check valve C85, and is suctioned into a suctionheader 150 for distribution to natural gas compressors 180, 210. Thecompressors 180, 210 are driven by prime movers 160, 190 via powertransfer couplings 170, 200, respectively, to pressurize the natural gasstreams. The high pressure natural gas streams exit the compressors 180,210 into a discharge header 220, and then are cooled by an aftercooler225, flowed through check valve C290, and metered by an orifice meterM300 before transferring to a wet gas sales line 230 via transfer line285. The pressurized natural gas stream can also be recycled by openingcontrol valves V250, V260 and at least partially closing control valveV287 to cycle the pressurized natural gas stream back into thecompressors 180, 210 via lines 240, 270.

While the foregoing is directed to certain embodiments, other andfurther embodiments may be devised without departing from the basicscope of this disclosure.

1. A method of injecting a treatment fluid into a hydrocarbon bearingreservoir, comprising: mixing an unfractionated hydrocarbon liquidmixture and a chemical additive, wherein the unfractionated hydrocarbonliquid mixture is a by-product of a de-methanized hydrocarbon stream andcomprises ethane, propane, butane, isobutane, pentane, and less than onepercent methane by liquid volume, wherein the unfractionated hydrocarbonliquid mixture is sourced and transported from a separate processingfacility that is located at a location remote from the hydrocarbonbearing reservoir, wherein the separate processing facility comprises atleast one of a splitter facility, a gas plant, and a refinery, whereinthe unfractionated hydrocarbon liquid mixture is transported viapressure storage vessels from the separate processing facility to thehydrocarbon bearing reservoir; pressurizing the unfractionatedhydrocarbon liquid mixture and the chemical additive with a first pump;pressurizing a liquefied gas with a second pump; vaporizing theliquefied gas with a vaporizer; mixing the pressurized, vaporized gaswith the pressurized, unfractionated hydrocarbon liquid mixture andchemical additive to form a treatment fluid; and pumping the treatmentfluid into the hydrocarbon bearing reservoir at a pressure greater thana formation pressure of the hydrocarbon bearing reservoir.
 2. The methodof claim 1, further comprising mixing water with the unfractionatedhydrocarbon liquid mixture and the chemical additive, wherein the watercomprises 5-10% inhibited water by volume.
 3. The method of claim 1,wherein the chemical additive comprises a surfactant, a non-ionicsurfactant, a polymer, an acid, a nano-surfactant, a nano-polymer, apolymer coated nano-particle, a nano-solvent, or combinations thereof,and wherein the liquefied gas comprises nitrogen, carbon dioxide, orcombination thereof.
 4. The method of claim 1, wherein the pressure thatthe treatment fluid is pumped into the hydrocarbon bearing reservoir isbetween 250 psig and 10,000 psig.
 5. The method of claim 1, furthercomprising injecting the treatment fluid into contact with paraffin,asphaltene, or condensate blockage located in the hydrocarbon bearingreservoir.
 6. The method of claim 1, further comprising freezing connatewater located in the hydrocarbon bearing reservoir using the treatmentfluid, pumping additional treatment fluid into the hydrocarbon bearingreservoir, and diverting the additional treatment fluid using the frozenconnate water to a selected location in the hydrocarbon bearingreservoir.
 7. The method of claim 1, wherein the unfractionatedhydrocarbon liquid mixture further comprises condensate, water, carbondioxide, nitrogen, hydrogen sulfide, or combinations thereof.
 8. Themethod of claim 1, wherein the second pump is a cryogenic pump.
 9. Themethod of claim 1, wherein the pressurized, vaporized gas cools thepressurized, unfractionated hydrocarbon liquid mixture and chemicaladditive to form the treatment fluid before pumping the treatment fluidinto the hydrocarbon bearing reservoir.
 10. The method of claim 9,wherein the treatment fluid is cooled to a temperature of 0 degreesFahrenheit or lower; and further comprising freezing connate waterlocated in the hydrocarbon bearing reservoir using the cooled treatmentfluid, pumping additional treatment fluid into the hydrocarbon bearingreservoir, and diverting the additional treatment fluid using the frozenconnate water to a selected location in the hydrocarbon bearingreservoir.
 11. The method of claim 1, further comprising diverting thetreatment fluid flow within the hydrocarbon bearing reservoir using adiverting agent.
 12. The method of claim 11, wherein the diverting agentcomprises a polymer.
 13. A method of injecting a treatment fluid into ahydrocarbon bearing reservoir, comprising: pressurizing anunfractionated hydrocarbon liquid mixture with a first pump, wherein theunfractionated hydrocarbon liquid mixture is a by-product of ade-methanized hydrocarbon stream and comprises ethane, propane, butane,isobutane, pentane, and less than one percent methane by liquid volume,wherein the unfractionated hydrocarbon liquid mixture is sourced andtransported from a separate processing facility that is located at alocation remote from the hydrocarbon bearing reservoir, wherein theseparate processing facility comprises at least one of a splitterfacility, a gas plant, and a refinery, wherein the unfractionatedhydrocarbon liquid mixture is transported via pressure storage vesselsfrom the separate processing facility to the hydrocarbon bearingreservoir; pressurizing a liquefied gas with a second pump, wherein theliquefied gas comprises nitrogen, carbon dioxide, or combinationsthereof; vaporizing the liquefied gas with a vaporizer; mixing thepressurized, vaporized gas with the pressurized, unfractionatedhydrocarbon liquid mixture to form a treatment fluid; and pumping thetreatment fluid into the hydrocarbon bearing reservoir at a pressuregreater than a formation pressure of the hydrocarbon bearing reservoir.14. The method of claim 13, wherein the pressure that the treatmentfluid is pumped into the hydrocarbon bearing reservoir is between 250psig and 10,000 psig.
 15. The method of claim 13, further comprisingdiverting the treatment fluid flow within the hydrocarbon bearingreservoir using a diverting agent.
 16. The method of claim 15, whereinthe diverting agent comprises a polymer.
 17. A method of injecting atreatment fluid into a hydrocarbon bearing reservoir, comprising: mixingan unfractionated hydrocarbon liquid mixture, water, and a non-ionicsurfactant, wherein the unfractionated hydrocarbon liquid mixture is aby-product of a de-methanized hydrocarbon stream and comprises ethane,propane, butane, isobutane, pentane, and less than one percent methaneby liquid volume, wherein the unfractionated hydrocarbon liquid mixtureis sourced and transported from a separate processing facility that islocated at a location remote from the hydrocarbon bearing reservoir,wherein the separate processing facility comprises at least one of asplitter facility, a gas plant, and a refinery, wherein theunfractionated hydrocarbon liquid mixture is transported via pressurestorage vessels from the separate processing facility to the hydrocarbonbearing reservoir; pressurizing the unfractionated hydrocarbon liquidmixture, the water, and the non-ionic surfactant with a first pump;pressurizing a gas with a second pump, wherein the gas comprisesnitrogen, carbon dioxide, or combinations thereof; mixing thepressurized gas with the pressurized, unfractionated hydrocarbon liquidmixture, water, and non-ionic surfactant to form a treatment fluid; andpumping the treatment fluid into the hydrocarbon bearing reservoir at apressure greater than a formation pressure of the hydrocarbon bearingreservoir.
 18. The method of claim 17, wherein the pressure that thetreatment fluid is pumped into the hydrocarbon bearing reservoir isbetween 250 psig and 10,000 psig.
 19. The method of claim 17, furthercomprising diverting the treatment fluid flow within the hydrocarbonbearing reservoir using a diverting agent.
 20. The method of claim 19,wherein the diverting agent comprises a polymer.